Carbonate reservoirs worldwide are complex in structure, diverse in form, and highly heterogeneous. Based on these characteristics, the reservoir stimulation technologies and fluid flow characteristics of carbonate reservoirs are briefly described in this study. The development methods and EOR technologies of carbonate reservoirs are systematically summarized, the relevant mechanisms are analyzed, and the application status of oil fields is catalogued. The challenges in the development of carbonate reservoirs are discussed, and future research directions are explored. In the current development processes of carbonate reservoirs, water flooding and gas flooding remain the primary means but are often prone to channeling problems. Chemical flooding is an effective method of tertiary oil recovery, but the harsh formation conditions require high-performance chemical agents. The application of emerging technologies can enhance the oil recovery efficiency and environmental friendliness to a certain extent, which is welcome in hard-to-recover areas such as heavy oil reservoirs, but the economic cost is often high. In future research on EOR technologies, flow field control and flow channel plugging will be the potential directions of traditional development methods, and the application of nanoparticles will revolutionize the chemical EOR methods. On the basis of diversified reservoir stimulation, combined with a variety of modern data processing schemes, multichannel EOR technologies are being developed to realize the systematic, intelligent, and cost-effective development of carbonate reservoirs.

In recent years, studies conducted on foam stabilization have focused on nanoparticles by generating strong adsorption at the interface to stabilize the foam under harsh reservoir conditions. Meanwhile, the selection of a gas source is also of great importance for foam performance. In this study, a mixed system of surfactants was selected, and the foamability and foam stability of nitrogen and methane were evaluated according to the improved jet method. After adding modified SiO 2 nanoparticles, the foam-related parameters were analyzed. The plugging abilities of the different foams were compared through core-flooding experiments, and the oil displacement effects of the different foams were compared through microfluidic experiments. The results show that the amphoteric surfactant betaine has an excellent synergistic effect on the anionic surfactant SDS. The methane foam produced using the jet method has a larger initial volume than the nitrogen foam, but its stability is poor. The half-life of the nitrogen foam is about two times that of the methane foam. After adding 1.0 wt % SiO 2 nanoparticles to the surfactant solution, the viscosity and stability of the formed foam improve. However, the maximum viscosity of the surfactant nanoparticle foam (surfactant-NP foam) is 53 mPa·s higher than that of the surfactant foam. In the core-flooding experiment, the plugging performance of the methane foam was worse than that of the nitrogen foam, and in the microfluidic experiment, the oil displacement abilities of the methane foam and the nitrogen foam were similar. The plugging performance and the oil displacement effect of the foam are greatly improved by adding nanoparticles. The surfactant-NP foam flooding has a better oil displacement effect and can enhance the recovery factor by more than 30%. Under actual high-pressure reservoir conditions, although the stability of the methane foam is weaker than that of the nitrogen foam, some methane may be dissolved in the crude oil to decrease the viscosity after the foam collapses, which leads to the methane foam being the preferred method in oilfields.

Currently, thermal oil recovery methods are commonly applied to heavy oil development. Microwave heating is an effective recovery method and has the advantages of rapid heat transfer, volumetric heating, and selective heating. In the process of using microwaves to extract heavy oil, catalyst-assisted microwaves for oil viscosity reduction are adopted. In this study, magnetic graphene oxide (MGO) with a good load is prepared using a charge self-assembly method. The MGO is then characterized using scanning electron microscopy, X-ray diffraction, Fourier-transform infrared spectroscopy, and X-ray photoelectron spectroscopy. Next, the dispersibility of MGO in water with increasing microwave treatment time is studied using ultraviolet spectrometry. Finally, using microwaves, the heavy oil viscosity reduction effect of MGO and the oil displacement effect of MGO fluid are tested. The results revealed that MGO is a catalyst supported by ferroferric oxide nanoparticles (denoted as nano-Fe3O4) on graphene oxide. Its loadability and dispersibility in water are good. With an increase in the radiation duration of the microwaves, its dispersibility in water deteriorates and magnetic-reduced graphene oxide (MRGO) forms, which exhibits lipophilicity and better microwave absorption performance than MGO. However, MGO performs well in heavy oil viscosity reduction using auxiliary microwaves. The viscosity reduction rate reached 43.61% after 10 min of microwave treatment when adding a hydrogen donor, and the heavy oil was modified to increase the content of light components. Furthermore, MGO fluid flooding was found to have a higher recovery efficiency under microwave irradiation compared with conventional water flooding. The thermal stress generated by the microwaves caused the oil and water to retransport in the porous medium, blocking some of the turbulent channels, which increased the swept volume of the subsequent displacement. In addition, the lipophilic MRGO produced under microwave treatment approached the oil spontaneously and, together with the loaded Fe3O4, reacted on the oil to reduce its viscosity. This was beneficial for the separation and shedding of the oil from the attachment. Therefore, MGO-assisted microwave treatment can potentially be used to enhance oil recovery.

Foam is widely used in fractured reservoirs. However, few studies on the flow characteristics of foam fluid in fractures have been presented, and the flow mechanism of foam in complex fracture networks remains unclear. In this study, a variety of fracture models are used to systematically evaluate the flow characteristics of foam in fractures. First, based on the variable-thickness fracture and parallel fracture models, the variations in foam flow resistance and velocity are explored. Then, the foam flow path and sweep efficiency are evaluated with complex fracture network models. The results show that the foam flow resistance increases with increasing foam quality. At a higher foam quality (90%−92%), the pressure drop peaks and then decreases sharply as the foam quality increases. When the foam quality ranges from 50% to 90%, the foam volume increases with increasing foam quality, and the bubbles have larger diameters in thicker fractures. When foam flows in parallel fractures with different thicknesses, it preferentially flows in thick fractures (100 μm), and gas trapping occurs in the thin fractures. When the foam flows in a complex fracture network, the pressure drop increases with increasing foam quality and flow rate, and the foam quality corresponding to the maximum pressure drop is independent of the flow rate. In the vertical intersecting fracture network model, the range of flowing foam is the most extensive when the foam quality is 80%−90%. In the irregular fracture network model, when the foam quality reaches 92%, the volumetric sweep efficiency reaches a maximum of 86.97%. These findings reflect that it is necessary to consider fractures when foam flows in fractured/vuggy reservoirs and that reasonable predictions can be made with experimental results.

In this article, experiments and simulations were conducted to evaluate performance of surfactant-nanoparticles foam for enhanced oil recovery under high temperature. Experimentally, the displacement behavior of surfactant-nanoparticles foam for enhanced oil recovery was studied by micromodel tests at 90 °C. The recovery performance of surfactant-nanoparticles foam flooding was analyzed by sandpack flooding experiments at 150 °C. Theoretically, a mechanistic model of surfactant-nanoparticles foam flooding was constructed. The micromodel tests indicate that the surfactant-nanoparticles foam was more stable than that of the surfactant foam in the porous media at 90 °C. The surfactant-nanoparticles foam could accumulated in the pores with less oil and increase the swept area. The crude oil could be emulsified into oil droplets by surfactant-nanoparticles foam which can greatly enhance the oil recovery. The sandpack flooding results show that the surfactant-nanoparticles foam had better recovery performance at 150 °C. Compared with the surfactant foam, the surfactant-nanoparticles foam produced from the sandpack flooding experiment had a smaller average particle size and higher sphericity. A mechanistic model of surfactant-nanoparticles foam flooding was constructed. A good match was achieved between the numerical simulation and sandpack flooding experiments in terms of pressure and oil recovery by adjusting the model parameters. The simulation study indicates that the performance of surfactant-nanoparticles foam flooding is better than that obtained by surfactant foam flooding under high temperature.